IR 05000280/2026090
| ML26075C435 | |
| Person / Time | |
|---|---|
| Site: | Surry  (DPR-032, DPR-037) |
| Issue date: | 03/30/2026 |
| From: | Mark Franke NRC/RGN-II/DORS/PB6 |
| To: | Carr E Dominion Energy |
| Shared Package | |
| IR 2026090 | List: |
| References | |
| EAF-RII-2026-0006 IR 2026090 | |
| Download: ML26075C435 (0) | |
Text
SUBJECT:
SURRY POWER STATION - NRC INSPECTION REPORT 05000280/2026090 AND 05000281/2026090 AND PRELIMINARY WHITE FINDING AND APPARENT VIOLATION
Dear Eric S. Carr:
The enclosed inspection report documents a finding with an associated violation that the U.S.
Nuclear Regulatory Commission (NRC) has preliminarily determined to be of low (White) safety significance. The finding involved the failure to provide written procedures with appropriate instructions necessary to perform turbine driven auxiliary feedwater pump maintenance activities. We assessed the significance of the finding using NRCs significance determination process (SDP) and the best available information. The attachment to the inspection report contains a detailed risk evaluation with the basis of our preliminary significance determination.
The finding is also an apparent violation of NRC requirements and is being considered for escalated enforcement action in accordance with the Enforcement Policy, which can be found at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html.
In accordance with NRC Inspection Manual Chapter 0609, we intend to complete our evaluation using the best available information and issue our final determination of safety significance within 90 days of the date of this letter. The NRCs SDP is designed to encourage an open dialogue between your staff and the NRC; however, neither the dialogue nor the written information you provide should affect the timeliness of our final determination.
Before we make a final decision on this matter, we are providing you with an opportunity to (1) attend a Regulatory Conference where you can present to the NRC your perspective on the facts and assumptions the NRC used to arrive at the finding and assess its significance, or (2) submit your position on the finding to the NRC in writing. If you request a Regulatory Conference, it should be held within 40 days of receipt of this letter, and we encourage you to submit supporting documentation at least one week prior to the conference to make the conference more efficient and effective. The focus of the Regulatory Conference is to discuss the significance of the finding and not necessarily the root cause(s) or corrective action(s)
associated with the finding. If a Regulatory Conference is held, it will be open for public observation. If you decide to submit only a written response, such submittal should be sent to the NRC within 40 days of your receipt of this letter. If you decline to request a Regulatory March 30, 2026 Conference or to submit a written response, you relinquish your right to appeal the final SDP determination, in that by not doing either, you fail to meet the appeal requirements stated in the Prerequisite and Limitation sections of Attachment 2 of NRC Inspection Manual Chapter 0609.
If you choose to send a response, it should be clearly marked as a "Response to Apparent Violation; (EAF-RII-2026-0006)" and should include for the apparent violation: (1) the reason for the apparent violation or, if contested, the basis for disputing the apparent violation; (2) the corrective steps that have been taken and the results achieved; (3) the corrective steps that will be taken; and (4) the date when full compliance will be achieved. Your response should be submitted under oath or affirmation and may reference or include previously docketed correspondence, if the correspondence adequately addresses the required response.
Additionally, your response should be sent to the U.S. Nuclear Regulatory Commission, ATTN:
Document Control Center, Washington, DC 20555-0001 with a copy to Steven Smith, Chief, Projects Branch 6, U.S. Nuclear Regulatory Commission, Region II, 245 Peachtree Center Avenue N.E, Suite 1200, Atlanta, GA 30303-1200 within 40 days of the date of this letter. If an adequate response is not received within the time specified or an extension of time has not been granted by the NRC, the NRC will proceed with its enforcement decision or schedule a Regulatory Conference.
Please contact Steven Smith at 404-997-4890, and in writing, within 10 days of the issue date of this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we will continue with our significance determination and enforcement decision. The final resolution of this matter will be conveyed in separate correspondence.
Because the NRC has not made a final determination in this matter, no Notice of Violation is being issued for this inspection finding at this time. In addition, please be advised that the number and characterization of the apparent violation described in the enclosed inspection report may change as a result of further NRC review.
For administrative purposes, the enclosed inspection report provides an update to the apparent violation documented in NRC inspection report 05000280/2025004 and 05000281/2025004, dated February 5, 2026, and accessible at http://www.nrc.gov/reading-rm/adams.html via ADAMS Accession Number ML26036A044. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding.
Sincerely, Mark E. Franke, Director Division of Operating Reactor Safety Docket Nos. 05000280 and 05000281 License Nos. DPR-32 and DPR-37
Enclosure:
Inspection Report No. 05000280/2026090 and 05000281/2026090 w/ Attachment
Inspection Report
Docket Numbers:
05000280 and 05000281
License Numbers:
Report Numbers:
05000280/2026090 and 05000281/2026090
Enterprise Identifier:
I-2026-090-0005
Licensee:
Dominion Energy
Facility:
Surry Power Station
Location:
Surry, VA
Inspection Dates:
November 19, 2025, to March 6, 2026
Inspectors:
D. Jung, Resident Inspector
A. Rosebrook, Senior Reactor Analyst
D. Turpin, Senior Resident Inspector
Approved By:
Mark E. Franke, Director
Division of Operating Reactor Safety
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees
performance by conducting a NRC inspection at Surry Power Station, in accordance with the
Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for
overseeing the safe operation of commercial nuclear power reactors. Refer to
https://www.nrc.gov/reactors/operating/oversight.html for more information.
List of Findings and Violations
Failure to provide detailed maintenance procedures for the turbine driven auxiliary feedwater
pump to ensure safety of the reactor
Cornerstone
Significance
Cross-Cutting
Aspect
Report
Section
Preliminary White
AV 05000280,05000281/2025004-01
Open
EAF-RII-2026-0006
[H.1] -
Resources
A self-revealed preliminary White (low safety significance) finding and associated apparent
violation of Technical Specification (TS) 6.4.A.7, Unit Operating Procedures and Programs,
was identified when the licensee failed to provide detailed written procedures with appropriate
instructions to perform maintenance activities, which resulted in the failure of a Unit 1 and Unit
2 TS surveillance test for the turbine driven auxiliary feedwater pumps (TDAFWPs).
Additional Tracking Items
None.
INSPECTION SCOPES
Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in
effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with
their attached revision histories are located on the public website at http://www.nrc.gov/reading-
rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared
complete when the IP requirements most appropriate to the inspection activity were met
consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection
Program - Operations Phase. The inspectors reviewed selected procedures and records,
observed activities, and interviewed personnel to assess licensee performance and compliance
with Commission rules and regulations, license conditions, site procedures, and standards.
INSPECTION RESULTS
Failure to provide detailed maintenance procedures for the turbine driven auxiliary feedwater
pump to ensure safety of the reactor
Cornerstone
Significance
Cross-Cutting
Aspect
Report
Section
Mitigating Systems Preliminary White
AV 05000280,05000281/2025004-01
Open
EAF-RII-2026-0006
[H.1] -
Resources
A self-revealed preliminary White (low safety significance) finding and associated apparent
violation of Technical Specification (TS) 6.4.A.7, Unit Operating Procedures and Programs,
was identified when the licensee failed to provide detailed written procedures with appropriate
instructions to perform maintenance activities, which resulted in the failure of a Unit 1 and Unit
2 TS surveillance test for the turbine driven auxiliary feedwater pumps (TDAFWPs).
Description: On January 14, 2025, Unit 1 TDAFWP started and tripped on overspeed after
approximately 5 seconds while performing the quarterly TS surveillance testing. The licensee
restored operability by replacing the governor.
On February 18, 2025, Unit 2 TDAFWP also tripped on overspeed during the quarterly TS
surveillance testing. The licensee restored operability by adjusting the governor compensating
needle valve. The licensee determined that the most probable cause of the overspeed trip was
due to the compensating needle valve on the governor not being set to its optimal position
following the governor oil change activity during the Unit 2 refueling outage in November 2024.
During the planned Unit 2 TDAFWP governor maintenance activity on November 8, 2024,
maintenance procedure 0-MCM-1403-01 did not clearly require governor venting and
compensating needle valve optimization following the governor oil change activity. Step 6.11.5
of the procedure states, IF Step 6.11.3 [governor oil change] was the only Step performed and
governor change out or maintenance was not performed, THEN enter N/A for Subsection 6.12
[compensating needle valve optimization] and proceed to Subsection 6.13 [governor and
operational checks]. However, the licensee stated in their level of effort evaluation that the
venting of the governor is an expected practice after an oil change to remove air in the oil
system per the Electric Power Research Institute guidance and the Vendor Technical Manual.
The procedure also provided contradicting guidance and written instructions which resulted in
a failure to perform governor venting or compensating needle valve optimization.
Following the February 2025 Unit 2 TDAFWP failure, the licensee conducted an in-depth
inspection of the Unit 1 TDAFWP on March 13, 2025. The licensee determined the most
probable cause of the Unit 1 TDAFWP overspeed trip was due to improper governor valve
maintenance performed in May 2021. Specifically, during the scheduled Unit 1 TDAFWP
maintenance activity on May 14, 2021, maintenance personnel performed a tightening of the
set screw that secures the guide bushing in place per the procedure 0-MCM-1403-01, Terry
Turbine Overhaul, 1-FW-T-2 and 2-FW-T-2. The procedure contains instructions to tighten
set screw throughout the procedure without specific instruction or guidance on expected
tightness or validation of the proper installation of the set screw. This resulted in damage to the
guide bushing threads and led to slight misalignment on the valve stem. The misalignment
introduced excessive friction forces in the governor valve, stem, and associated packing,
degrading performance over time and ultimately causing the overspeed trip.
The inspectors concluded that the licensee failed to provide procedures with appropriate
instructions to perform TDAFWP maintenance activities. Specifically, the instructions were
inappropriate in that performance of the instructions resulted in an overtightened set screw,
which introduced excessive friction force in the governor valve, stem, and associated packing,
resulting in the turbine overspeed trip during Unit 1 TDAFWP quarterly surveillance testing.
Furthermore, the failure to provide appropriate instructions on when to perform the governor
venting and compensating needle valve optimization resulted in the turbine overspeed trip
during Unit 2 TDAFWP quarterly surveillance testing.
Corrective Actions: The licensee completed immediate corrective actions to restore the plant
equipment to the expected state and revised the affected procedure to include additional
details and guidance for future maintenance activities. Also, the licensee completed a level of
effort evaluation of the events and initiated a root cause evaluation.
Corrective Action References: CR1280548 and 1283327
Performance Assessment:
Performance Deficiency: The inspectors determined that the licensees failure to provide a
detailed written procedure with appropriate instructions was a performance deficiency that was
reasonably within the licensees ability to foresee and correct. Specifically, the licensee did not
provide appropriate written procedures for preventive maintenance operations which resulted
in the failure of the Unit 1 and Unit 2 TDAFWP TS surveillance tests.
Screening: The inspectors determined the performance deficiency was more than minor
because it was associated with the Procedure Quality attribute of the Mitigating Systems
cornerstone and adversely affected the cornerstone objective to ensure the availability,
reliability, and capability of systems that respond to initiating events to prevent undesirable
consequences. Specifically, the performance of the procedure contributed to TS surveillance
failures of both Unit 1 and Unit 2 TDAFWPs.
Significance: The inspectors assessed the significance of the finding using IMC 0609,
Appendix AProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>Appendix A" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., The Significance Determination Process (SDP) for Findings At-Power. The
inspectors assessed the significance of the finding using IMC 0609, Attachment 04, Initial
Characterization of Findings, and determined that the finding was associated with the
Mitigating Systems cornerstone. Using IMC 0609, Appendix A, The Significance
Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening
Questions, Section A, the screening question A.2 was answered YES, which directed staff to
perform a detailed risk evaluation.
A Region II Senior Reactor Analyst performed a detailed risk evaluation. The finding was
determined to be preliminarily of low safety significance (White) due to the Unit 2 change in
core damage frequency being at 1.47E-06/year. The risk estimate was obtained by performing
a conditional failure analysis of the TDAWFP using a 75-day exposure period for Unit 2 and a
42-day exposure period for Unit 1. The dominant sequences were associated with fire
sequences on the H emergency bus and weather-related loss of offsite power events, failure of
the emergency diesel generators, failure to restart the affected TDAFWP, and failure of feed
and bleed cooling for the primary. See Attachment, "TURBINE DRIVEN AUXILIARY
FEEDWATER PUMPS DETAILED RISK EVALUATION," for a summary of the basis for the
preliminary risk determination.
Cross-Cutting Aspect: H.1 - Resources: Leaders ensure that personnel, equipment,
procedures, and other resources are available and adequate to support nuclear safety.
Specifically, during the maintenance activities for the Units 1 and 2 TDAFW pumps, the
maintenance personnel did not have adequate proficiency to perform the task without
additional procedural guidance which caused the overtightening of the set screw on the
governor valve. Also, the maintenance personnel did not have adequate guidance to recognize
when to perform the governor venting and compensating needle valve optimization, which
caused the suboptimal compensating needle valve position.
Enforcement:
Violation: Technical Specification 6.4.A.7, Unit Operating Procedures and Programs,
requires, in part, Detailed written procedures with appropriate check-off lists and instructions
shall be provided for the following conditions[p]reventive or corrective maintenance
operations which would have an effect on the safety of the reactor.
Contrary to the above, on or before November 8, 2024, the licensee failed to provide detailed
written procedures with appropriate instructions to perform preventive maintenance activities
on the Unit 1 and Unit 2 TDAFWPs. Specifically, on May 14, 2021, during a planned
maintenance activity on the Unit 1 TDAFWP, the instructions were inappropriate in that
performance of the instructions resulted in overtightening of a set screw, rendering the pump
inoperable for a period longer than the allowed TS outage time, as revealed by the failure of a
quarterly TS surveillance test on January 14, 2025. Additionally, on November 8, 2024, during
a planned maintenance activity on the Unit 2 TDAFWP, the licensee failed to provide
appropriate maintenance instructions which resulted in the pumps governor compensating
needle valve being left in a configuration that rendered the pump inoperable from December 5,
2024, to February 19, 2025, as revealed by the failure of a quarterly TS surveillance test on
February 18, 2025.
Enforcement Action: This violation is being treated as an apparent violation pending a final
significance (enforcement) determination.
Attachment
TURBINE DRIVEN AUXILIARY FEEDWATER PUMPS DETAILED RISK EVALUATION
OVERALL RISK SUMMARY
The Surry Unit 1 turbine driven auxiliary feedwater pump (TDAFWP) was rendered inoperable
due to tripping on an invalid overspeed condition most probably caused by improper governor
valve maintenance. Following that event, the Surry Unit 2 TDAFWP was rendered inoperable
due to tripping on an invalid overspeed condition most probably caused by the compensating
needle valve on the governor not being set to its optimal position. A risk evaluation that
considered the exposure period of these conditions, including the overlap period when both
conditions existed, estimated an increase in core damage frequency (delta-CDF) of 1.47E-
06/year (consistent with a White finding) for Unit 2, and a delta-CDF of 8.31E-07/year
(consistent with a Green finding) for Unit 1.
EXPOSURE TIME
For Unit 1, the last successful demonstration of operability was a surveillance test on
October 24, 2024. The issue was discovered and addressed on January 16, 2025, resulting in a
period of 84 days. The licensee proved via engineering analysis, laboratory testing, and
subsequent surveillance runs that there was a time dependent nature for the internal resistance
forces which caused the total resistance to be greater than the governor capacity. Therefore, an
exposure period of T/2 + repair time (42 days for Unit 1) was used for the analysis consistent
with the guidance discussed in Section 2.4 of Volume 1 of the Risk Assessment Standardization
Project (RASP) handbook (ADAMS ML17348A149).
For Unit 2, the adverse condition definitively was introduced on November 8, 2024, when the
maintenance activities were performed. However, the TDAFWP was not in a required mode of
operability since Unit 2 was in a refueling outage until December 5, 2024. Therefore, the
exposure period used was from the post maintenance testing (PMT) performed on December 5,
2024, until discovery on February 19, 2025 (75 days for Unit 2). In this case, T was used for the
analysis consistent with the guidance discussed in Section 2.3 of Volume 1 of the RASP
handbook, because the onset of the condition was known.
Since Unit 1 and Unit 2 auxiliary feedwater (AFW) systems can be cross connected, it was
determined there was a 40-day period where there was an overlap and both TDAFWPs were in
a degraded state concurrently. There were 2 days when Unit 1 was the only unit affected (Unit 2
was in an outage) and 35 days when Unit 2 was the only unit affected (after the Unit 1 condition
was identified and addressed).
SAFETY IMPACT
Affected structures, systems, components (SSCs), operator actions, and risk-relevant functions:
Unit 1 and 2 turbine driven auxiliary feedwater pumps. The probabilistic risk assessment (PRA)
function is to maintain secondary side cooling for decay heat removal. In both cases, the
performance deficiency would cause the affected TDAFWP to trip on overspeed during a start
demand.
Attachment
RISK ANALYSIS/CONSIDERATIONS
1.
The Surry Standardized Plant Analysis Risk (SPAR) model is set up to model Unit 1 risk;
therefore, when modeling Unit 2 risk, Unit 1 components were used as surrogates. However,
in systems such as AFW, Unit 2 components represent the cross-unit capabilities.
2.
Flexible Coping (FLEX) mitigating strategies and equipment were credited in the analysis in
both the nominal and conditional cases.
3.
Recovery credit was applied for a TDAFWP fail-to-start (FTS). The TDAFWP fault tree was
modified to account for recovery. Two basic events were created to accomplish this.
4.
A Human Error Probability (HEP) basic event (AFW-XHE-XL-TDAFWROSRESET) was
created to model operators failing to reset the TDAFWP following an overspeed trip. This
HEP was assigned a value of 3.86E-03 using IDEAHS-ECA and work performed for a
similar HEP for a turbine-driven emergency feedwater issue at another Dominion plant (V.C.
Summer). The licensee used a value of 1E-02 when they added recovery to their model for
comparison.
5.
AFW-TDP-FS-1P2RESTARTNV, AFW TURBINE DRIVEN PUMP 1-FW-P-2 FAILS TO RE-
START WITH NEEDLE VALVE OOP: This is the probability the TDAFWP will fail to restart
since the condition was still present. For Unit 2, the adverse condition was known to exist
during four demands on the system. Three starts were successful and the fourth start failed.
Performing a Bayesian update, a Constrained Non-Informative (CNI) was used based upon
the number of demands and number of failures. This resulted in a probability of 1.67E-01
with a beta distribution and beta factor of 7.5. While based on Unit 2 data, this factor was
applied to Unit 1 as well as a bounding value. This was conservative and did not impact the
conclusions for Unit 1 risk.
6.
Recovery was modeled in the fault tree in accordance with the guidance in Section 6.5.5 of
Volume 1 of the RASP handbook. Common cause failures (CCFs) of both TDAFWPs were
not modeled as a basic event. Only the CCF probability of the pump elements of all AFW
pumps (motor driven and turbine driven) were modeled, which affected failure to run only.
7.
Recovery credit was only applied to the affected unit and not the cross unit during the
overlap period. The basis for this was that during an event operators would have to choose
one TDAFWP to attempt to recover. Since both pumps cannot be aligned to the same
header, attempting to recover both pumps is unlikely to occur in core damage sequences of
under two hours. Additionally, if the initiating event affected both units (i.e., sitewide loss of
offsite power due to grid or weather), the cross unit TDAFWP would not be available to be
cross connected since it would be needed for that unit. The SPAR logic does not take this
into account.
8.
While reviewing differences between the licensees Computer Aided Fault Tree Analysis
System (CAFTA) model and the NRCs SPAR model, it was identified that the licensee used
a different value for DC battery test and maintenance (TM). The NRCs value was based on
single unit data, and the licensees value included consideration that the licensee can cross
connect the batteries during periods of maintenance. This design feature was verified in the
Surry Updated Final Safety Analysis Report (UFSAR) and considered the licensees figure
to be best available. Change set BATTTMLICENSEE-BATT TM at the licensees value was
added to include this in both the nominal and conditional cases.
9.
While reviewing dominant cut sets and comparing them to the licensees models, it was
identified that fault trees DCP-1A-125V-LATE, 125V BUS 1A DC POWER SYSTEM FAILS-
LONG TERM, and DCP-1B-125V-LATE, 125V BUS 1B DC POWER SYSTEM FAILS-LONG
TERM contained a logic gate (PSA-LOGIC-OVERLAY) which failed the associated battery.
This fault tree is used for feed and bleed operations which would be performed prior to two
hours. If FLEX strategies are successful such as deep load shedding and repowering the
vital battery chargers, this function would be maintained. Therefore, change set
PSALOGICGATE, Remove PSA logic gate for battery failure, was created, which changed
the logic from True to False in both the nominal and conditional cases.
10. While reviewing dominant cut sets and comparing them to the licensees model, it was
identified that the basic event PPR-MOV-AP-RC1535, BLOCK VALVE 1535 CLOSED DUE
TO PORV LEAKING was a common contributor to risk. The SPAR model used a value of
3.0E-01 for both motor operated valves (MOVs) RC-1535 and RC-1536 with no basis
provided. The licensee used values based on actual plant data from 2010 to 2015, 2.24E-01
for RC-1535 and 7.62E-02 for RC-1536. Actual plant data from a more representative time
frame of 2023 to 2025 was reviewed and it was determined that the licensees values were
not reflective of recent plant performance. Specifically, RC-1536 was closed for 90% of the
timeframe reviewed. Note: By Technical Specifications (TSs) the plant may operate with a
pressurizer power operated relief valve (PORV) isolated with the PORV considered to be TS
operable. As a result, the SPAR model values were considered to be best available.
11. The failures were modeled as AFW-TDP-FS-1P2, AFW TURBINE DRIVEN PUMP 1-FW-P-
2 FAILS TO START and AFW-TDP-FS-2P2, UNIT 2 AFW TD PUMP 2-FW-P-2 FAILS TO
START set to True (when in the 40-day overlay period) or AFW-TDP-FS-1P2, AFW
TURBINE DRIVEN PUMP 1-FW-P-2 FAILS TO START set to True (for single unit intervals).
12. While reviewing the dominant cut sets, it was identified that TDAFWP TM was in cut sets
where the TDAFWP restart had been successful. The TDAFWP cannot be in test and
maintenance if it already failed to start. Therefore, for the conditional case only, AFW-TDP-
TM-1P2, AFW TDP 1-FW-P-2 UNAVAILABLE DUE TO TEST AND MAINTENANCE was set
to False.
REPRESENTATIVE CASE CONDITIONAL CORE DAMAGE PROBABILITY (CCDP)
Systems Analysis Program for Hands-On Integrated Reliability Evaluations (SAPHIRE) software
Version 8.2.12 and Surry SPAR model Version 8.82 were used for the evaluation with model
adjustments to fault tree AFW-TDP to allow for recovery from an FTS basis on the condition
change sets -FLEX-CREDIT, BATTTMLICENSEE, and PSALOGICGATE were applied as
discussed above. Basic events AFW-TDP-FS-1P2, AFW TURBINE DRIVEN PUMP 1-FW-P-2
FAILS TO START and AFW-TDP-FS-2P2, UNIT 2 AFW TD PUMP 2-FW-P-2 FAILS TO START
were set to True for the overlap period. AFW-TDP-FS-1P2, AFW TURBINE DRIVEN PUMP 1-
FW-P-2 FAILS TO START was only set to True for the single unit periods. AFW-TDP-TM-1P2,
AFW TDP 1-FW-P-2 UNAVAILABLE DUE TO TEST AND MAINTENANCE was set to False.
Representative
Case for 40
Days Overlap
(Both Units)
Representative
Case for 35 Days
Single Unit
(Unit 2)
Representative
Case for 2 Days
Single Unit
(Unit 1)
Internal Event
4.82E-08
3.25E-08
1.86E-09
Internal Fire
5.14E-07
4.40E-07
2.51E-08
1.97E-07
1.72E-07
9.83E-09
Seismic
3.33E-08
2.92E-08
1.67E-09
Tornado/Hurricane/High Winds
3.05E-10
2.67E-10
1.53E-11
Interval Total
7.93E-07
6.74E-07
3.85E-08
Unit Totals
1.47E-06
Unit 2 (40 days
overlap + 35
days single unit
8.31E-07
Unit 1 (40 days
overlap + 2 days
single unit
EXTERNAL EVENTS CONSIDERATIONS
Internal event risk estimates without recovery were greater than 1E-07, therefore external
events were evaluated in the risk assessment. The Surry SPAR models contain well developed
models for internal flooding and internal fire scenarios using individual plant examination for
external events (IPEEE) data. The licensee was in the process of developing a fire PRA which
had not been completed at the time of the risk assessment. The assessment compared the
dominate cut sets and event sequences for the SPAR model results and the results were found
to be comparable. The SPAR model data was used as best available information. Results are
reflected in the above table.
SENSITIVITY EVALUATIONS
The following sensitivity evaluations were performed:
1.
Credit for recovery was varied by adjusting the TDAFW restart probability from no credit to
nominal FTS credit.
2.
Sensitivities were performed for basic events for 125V DC battery test and maintenance
using SPAR values, licensee values, and falsing out the basic event.
3.
Sensitivities were performed for basic events for PORV block valve MOVs shutting during
operation due to PORV leakage using SPAR values, licensee values, and falsing out the
basic events.
4.
Sensitivities were performed with the plant safety analysis (PSA) logic gate removed and not
removed.
All runs with both TDAFWP FTS (bounding)
Unit 1
(84 days)
Unit 1
(42 days)
Unit 2
(75 days)
No recovery or adjustments
7.25E-06
3.80E-06
6.55E-06
Recovery nominal only
2.12E-06
1.06E-06
1.89E-06
Recovery credit and both TDAFWPs FTS
and PORV block valves open (False)
1.92E-06
9.59E-07
1.71E-06
Recovery credit and both TDAFWPs FTS
and no Battery TM (False)
1.78E-06
8.91E-07
1.59E-06
Recovery credit and both TDAFWPs FTS
and No Battery TM and no PORV block
valves closed
1.58E-06
7.92E-07
1.41E-06
Both TDAFWPs FTS and no TDAFWP TM
with recovery
2.07E-06
1.04E-06
1.80E-06
Both TDAFWPs FTS and no TDAFWP TM
with recovery And PSA logic gate removed
for DCP LATE fault tree
1.93E-06
9.65E-07
1.72E-06
Both TDAFWPs FTS and no TDAFWP TM
with recovery and PSA logic gate removed
for DCP LATE fault tree. No Batt TM and
PORV block valves open.
1.53E-06
7.67E-07
1.37E-06
TDAFW fail to restart sensitivity using
the final representative case
Unit 1 (40
days overlap
+ 2 days
Unit 2 (40
days overlap
+ 35 days
single unit)
single unit)
Representative case
8.31 E-07
1.47E-06
Representative case with TDAFWP restart
x 0.5
7.5E-07
Representative case with TDAFWP restart
x 0.7
1.03E-06
Representative case with TDAFWP restart
at 1.14 (x 0.683) threshold point
1.00E-06
UNCERTAINTY ANALYSIS
The primary source of uncertainty was the restart probability given operator actions were
successful with the condition present. With the needle valve out of position, the governor
responds slower to oscillations and hunting, especially on rapid and large load changes and an
increased likelihood of nuisance trips on start up during the first few minutes of operations when
hunting is typically observed. Given the limited amount of actual data with the condition present
(four demands), calculating the probability of a second nuisance trip introduced a high level of
uncertainty to a term which is extremely sensitive. Additional testing could better define that
number and address this uncertainty. A Constrained Non-Informative (CNI) approach was used
vice a Jeffreys Non-Informative approach in this case. If a Jeffreys Non-Informative was used,
the results for the failure to restart would be 3E-01 vice 1.67 E-01 for the four-demand case (as
shown in the graphic above). This is because a Jeffreys Non-Informative starts with a mean of
0.5; therefore, the prior dominates the results with limited data. Even with ten demands the
Jeffreys Non-Informative results in 1.36E-01 verse 1.0 E-01 for the CNI. The CNI with a mean
of 1E-01 was used due to the limited amount of data/demands and characterization that this
condition would result in an increase in nuisance trips (estimated at 1 in 10). This approach was
used in previous risk evaluations of similar events at different sites.
LARGE EARLY RELEASE FREQUENCY (LERF) IMPACT
Using IMC 0609, Appendix H, Table 6.1, Phase I Screening-Type A Findings at Full Power, it
was determined that the dominant sequences and events would screen out in Phase 1.
Therefore, LERF was not a dominant contributor to risk.
CONCLUSIONS/RECOMMENDATIONS
The estimated risk increase (delta-CDF) for the inoperability of the TDAFWPs was 1.47E-
06/year for Unit 2, which should be preliminarily considered a finding of low safety significance
(White). The delta-CDF for Unit 1 was 8.31E-07/year (consistent with a Green finding).